I. Technical Field
The present invention relates to a multi-phase flowmeter for measuring each phase flow rate of a three-phase flow consisting of gas and two kinds of liquid.
II. Description of the Related Art
Petroleum produced from a well in a deep-sea area or the like forms a mixed-phase flow containing oil, water, and gas (which is a three-phase flow, hereinafter referred to as a multi-phase flow). Without separating those phases from each other, the petroleum is transferred under high pressure to the land, and then undergoes a development-well extraction process before being refined through separation. The oil and gas thus obtained through separation and refinement are transferred to a destination, with the water being discharged. Prior to the development-well extraction process, flow rate measurement for each phase is effected as needed on the multi-phase fluid for the purpose of development-well management and extraction or shipping management.
Regarding this flow rate measurement for each phase, there has been disclosed, for example, in the prior-art section of JP 2001-165741 A, a method based on a cross-correlation method utilizing a density meter and an ultrasonic flowmeter. In the disclosed technology, a gamma ray density meter is used as the density meter. As is known, the gamma ray density meter is expensive. In the cross-correlation method, the average density of the gas-liquid two-phase flow is measured by using the gamma ray density meter, and a void fraction is obtained from the measured average density. Then, from the void fraction and the volumetric flow rate of the multi-phase fluid measured by the ultrasonic flowmeter, each flow rate is obtained. In this case, by further adding an element for measuring a water content, it is possible to measure the flow rate of the oil and water. However, like the gamma ray density meter, the element for measuring a water cut is very expensive. Further, in most cases, it presupposes execution of calibration in the field, and hence there is a problem of a further increase in cost.
Apart from this, regarding the flow rate measurement of a multi-phase flow, there is known a method in which the multi-phase flow is turned into single-phase flows of gas, oil, water, etc. by a phase separation process (three-phase separation tank), and then the gas flow rate and the flow rates of the oil and water are measured (see JP 2003-513234 A). However, this measurement of each phase flow rate has a problem in that it involves high equipment cost for phase separation. In addition to the high equipment cost, the method has a problem in that the equipment is rather large and cannot be easily transferred to a place where it is needed.
Apart from this, JP 2003-513234 A discloses a technology regarding a density meter and the like. Application of this disclosed technology may help solve the above-mentioned problem of high cost through utilization of the disclosed technology regarding the density meter as disclosed in JP 2003-513234 A instead of the gamma type density meter. In JP 2003-513234 A, there are used Coriolis mass flowmeters as the flow meter and the density meter. It should be noted that a Coriolis mass flowmeter cannot simply be applied instead of the gamma type density meter. Further, the problem in JP 2003-513234 A should also be taken into account. Thus, in the following, the construction and operation of the multi-phase flowmeter of JP 2003-513234 A are briefly described.
In FIG. 11, a multi-phase flow measurement system (which corresponds to a multi-phase flowmeter) 100 includes a vortex separator 104, and an incoming multi-phase flow line 102 discharging a multi-phase fluid into the vortex separator 104. The vortex separator 104 discharges gas into an upper gas measurement flow line 106, and discharges liquid into a lower liquid measurement flow line 108. After flow measurement, the gas measurement flow line 106 and the liquid measurement flow line 108 join together again at a discharge flow line 110. Before the discharge flow line 110 reaches a sale site, the discharge flow line 110 extends to a three-phase production separator 118, making it possible to effect separation into a gas phase, a water phase, and an oil phase.
The multi-phase flow measurement system 100 is provided with a production manifold 116. The production manifold 116 is supplied with a multi-phase fluid from a plurality of oil wells or gas wells. The incoming multi-phase flow line 102 receives the multi-phase fluid from the production manifold 116 in the direction of the arrow 120. In the incoming multi-phase flow line 102, reference numeral 122 denotes a venturi section, reference numeral 124 denotes an incline/decline section, and reference numeral 126 denotes a horizontal discharge element with respect to the vortex separator 104.
The horizontal discharge element 126 is arranged so as to discharge the multi-phase fluid tangentially into the cylindrical interior separation section of the vortex separator 104. As is known, when the multi-phase fluid is discharged from the horizontal discharge element 126, a tornado effect or a cyclone effect is generated in a liquid portion 128 in the vortex separator 104 as a result of the discharge. The entire multi-phase fluid is discharged into the vortex separator 104 via the horizontal discharge element 126.
The liquid portion 128 is a majority liquid phase including the water phase and the oil phase obtained through separation and an entrained gas phase. The entrained gas phase is separated from the liquid portion 128 by a centrifugal force generated by a cyclone effect. The entrained gas phase cannot be completely removed except in the case of a relatively low flow rate allowing additional gravity separation of this entrained gas phase. In other words, in the case of a high flow rate, the entrained gas phase cannot be removed. The liquid portion 128 is discharged into the liquid measurement flow line 108 from the vortex separator 104.
A gas portion 132 in the vortex separator 104 is a majority gas phase including gas along with a mist consisting of oil and water. The vortex separator 104 is provided with a mist collecting screen 134 for causing partial condensation of the mist. The gas portion 132 is discharged into the gas measurement flow line 106.
The gas measurement flow line 106 is provided with a Coriolis mass flowmeter 154. The Coriolis mass flowmeter 154 provides measurement values of mass flow rate and density from the gas portion 132 of the multi-phase fluid inside the gas measurement flow line 106. The Coriolis mass flowmeter 154 is connected to a flow transmitter 156, and a signal indicating a measurement value is output to a controller 112. The gas measurement flow line 106 is provided with a check valve 160. The check valve 160 assures a positive flow in the direction of the arrow 162, whereby intrusion of the liquid portion 128 into the gas measurement flow line 106 is prevented.
The liquid measurement flow line 108 is provided with a static mixer 164. Further, on the output side of the static mixer 164, there are provided a Coriolis mass flowmeter 166 and a water cut monitor 172. The Coriolis mass flowmeter 166 provides measurement values of mass flow rate and density from the liquid portion 128 inside the liquid measurement flow line 108. The Coriolis mass flowmeter 166 is connected to a flow rate transmitter 168, and a signal indicating a measurement value is output to the controller 112. The water cut monitor 172 measures the water cut rate of the liquid portion 128 inside the liquid measurement flow line 108. The water cut monitor 172 is connected to the controller 112.
The liquid measurement flow line 108 is provided with a check valve 178. The check valve 178 assures a positive flow in the direction of the arrow 180, whereby it is possible to prevent intrusion of the gas portion 132 into the liquid measurement flow line 108. Reference numerals 150 and 174 denote valves controlled to be opened/closed by the controller 112.
The production manifold 116 has valves 182 and 184 controlled via a path 190. The valves 182 and 184 are selectively constructed such that a multi-phase fluid from an oil well 186 or from a well combination (e.g., oil well 186 and gas well 188) is caused to flow through a rail 192 and distributed to the incoming multi-phase flow line 102. The other valves are selectively constructed such that the fluid is caused to flow through a bypass flow line 194 to thereby bypass the multi-phase flow measurement system 100.
Reference numerals 196 and 197 denote manual valves. A bypass line 198 on the inner side of the valves 196 and 197 causes the flow to bypass the multi-phase flow measurement system 100 when a valve 199 is opened and the valves 150 and 174 are closed. The multi-phase flow measurement system 100 is constructed as described above.
JP 08-201130 A discloses a prior-art technology for measuring the flow rate of a two-phase fluid consisting of liquid and gas, etc. More specifically, the publication discloses a technology regarding a turbine flowmeter adapted to measure the flow rate of a two-phase fluid consisting of liquid and gas while the fluid is a mixed-phase flow (mixture liquid) consisting of liquid and gas. The turbine flowmeter has a function similar to that of the ultrasonic flowmeter described above, and can replace the same. As is known, there is attained an effect that the turbine flowmeter can perform measurement at low cost with an apparatus having a simple structure and being superior in durability. Apart from the turbine flowmeter and the ultrasonic flowmeter, an orifice flowmeter is also known.